Sealing Devices, Wellbore Tubulars Including The Sealing Devices, And Hydrocarbon Wells Including The Wellbore Tubulars

ABSTRACT

Sealing devices, wellbore tubulars including the sealing devices, and hydrocarbon wells including the wellbore tubulars are disclosed herein. The sealing devices include a sealing device body that is sized and shaped to operatively engage with an aperture in the wellbore tubular and to form an at least partial fluid seal with the aperture. The sealing device body has a hardness of 55-80 durometer, a tensile strength of 14-24 megapascals (MPa), a percent elongation of 250-500 percent, a 100% tensile stress of 1.4-5.2 MPa, and/or a die C tear resistance of 26-44 kilonewtons/meter (kN/m). The wellbore tubulars include an elongate tubular body, an aperture extending through the elongate tubular body, and a sealing device operatively engaged with the aperture. The hydrocarbon wells include a wellbore and the wellbore tubular extending within the wellbore.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application Ser. No. 62/411,890 filed Oct. 24, 2016, entitled “Sealing Devices, Wellbore Tubulars Including The Sealing Devices, And Hydrocarbon Wells Including The Wellbore Tubulars,” and U.S. Provisional Application Ser. No. 62/263,065 filed Dec. 4, 2015, entitled “Wellbore Ball Sealer And Methods Of Utilizing The Same,” and is also related to U.S. Provisional Application Ser. No. 62/262,034 filed Dec. 2, 2015, entitled, “Selective Stimulation Ports, Wellbore Tubulars That Include Selective Stimulation Ports, and Methods of Operating the Same,”;U.S. Provisional Application Ser. No. 62/262,036 filed Dec. 2, 2015, entitled, “Wellbore Tubulars Including A Plurality of Selective Stimulation Ports and Methods of Utilizing the Same,”; U.S. Provisional Application Ser. No. 62/263,067 filed Dec. 4, 2015, entitled, “Ball-Sealer Check-Valves for Wellbore Tubulars and Methods of Utilizing the Same,”; U.S. Provisional Application Ser. No. 62/263,069 filed Dec. 4, 2015, entitled, “Select-Fire, Downhole Shockwave Generation Devices, Hydrocarbon Wells That Include the Shockwave Generation Devices, and Methods of Utilizing the Same,”; and U.S. Provisional Application Ser. No. 62/329,690 filed Apr. 29, 2016, entitled, “System and Method for Autonomous Tools,” the disclosures of which are incorporated herein by reference in their entireties.

FIELD OF THE DISCLOSURE

The present disclosure relates generally to sealing devices, to wellbore tubulars including the sealing devices, and to hydrocarbon wells including the wellbore tubulars.

BACKGROUND OF THE DISCLOSURE

Hydrocarbon wells may include a wellbore that extends within a subterranean formation. The subterranean formation may include a reservoir fluid, such as a hydrocarbon fluid. With unconventional hydrocarbon reserves, it may be desirable to stimulate the subterranean formation, via the wellbore, to increase production of the reservoir fluid from the subterranean formation. This stimulation may be accomplished in a variety of ways. As an example, a stimulant fluid may be provided to the subterranean formation. As a more specific example, an acid may be pumped into the subterranean formation to dissolve portions of the subterranean formation, to increase a porosity of the subterranean formation, and/or to increase a fluid conductivity of the subterranean formation. As another example, a fracturing fluid may be provided to the subterranean formation to fracture portions of the subterranean formation, thereby increasing the fluid conductivity of the subterranean formation.

Stimulation operations may utilize an aperture, such as a perforation and/or hole, within a wellbore tubular that extends within the wellbore to provide the stimulant fluid to specific regions, or zones, of the subterranean formation. In addition, stimulation operations also may utilize a sealing device, such as a conventional ball sealer, to seal these apertures and/or to restrict fluid flow therethrough. Conventional ball sealers may be effective at sealing round apertures (i.e., apertures with a circular cross-section) but may be ineffective at sealing out-of-round, or oblong, apertures, such as may be generated by wear of the aperture during flow of the stimulant fluid therethrough. Thus, there exists a need for improved sealing devices, for wellbore tubulars including the sealing devices, and/or for hydrocarbon wells including the wellbore tubulars.

SUMMARY OF THE DISCLOSURE

Sealing devices, wellbore tubulars including the sealing devices, and hydrocarbon wells including the wellbore tubulars are disclosed herein. The sealing devices include a sealing device body that is sized and shaped to operatively engage with an aperture in the wellbore tubular and to form an at least partial fluid seal with the aperture. The sealing device body has a hardness of 55-80 durometer, a tensile strength of 14-24 megapascals (MPa), a percent elongation of 250-500 percent, a 100% tensile stress of 1.4-5.2 MPa, and/or a die C tear resistance of 26-44 kilonewtons/meter (kN/m).

The wellbore tubulars include an elongate tubular body, an aperture extending through the elongate tubular body, and a sealing device operatively engaged with the aperture. The elongate tubular body has an inner surface that defines a tubular conduit and an outer surface that is configured to face, or face toward, a subterranean formation. The aperture permits fluid communication between the tubular conduit and the subterranean formation. The sealing device forms an at least part fluid seal with the aperture to obstruct flow of a wellbore fluid from the tubular conduit into the subterranean formation.

The hydrocarbon wells include a wellbore and the wellbore tubular. The wellbore extends within a subterranean formation. The wellbore tubular extends within the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of a hydrocarbon well including a wellbore tubular with an aperture that may be at least partially sealed by a sealing device according to the present disclosure.

FIG. 2 is a schematic top view illustrating examples of apertures that may be sealed by sealing devices according to the present disclosure.

FIG. 3 is a schematic side view illustrating examples of a conventional sealing device sealing an aperture and/or of initial engagement between a sealing device, according to the present disclosure, and the aperture.

FIG. 4 is a schematic side view illustrating examples of a sealing device, according to the present disclosure, sealing the aperture of FIG. 3.

DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE

FIGS. 1-4 provide examples of sealing devices 70, according to the present disclosure, of wellbore tubulars 50 including an aperture 60 sealed by sealing devices 70, and/or of hydrocarbon wells 10 that include wellbore tubulars 50 and sealing devices 70. Elements that serve a similar, or at least substantially similar, purpose are labeled with like numbers in each of FIGS. 1-4, and these elements may not be discussed in detail herein with reference to each of FIGS. 1-4. Similarly, all elements may not be labeled in each of FIGS. 1-4, but reference numerals associated therewith may be utilized herein for consistency. Elements, components, and/or features that are discussed herein with reference to one or more of FIGS. 1-4 may be included in and/or utilized with any of FIGS. 1-4 without departing from the scope of the present disclosure. In general, elements that are likely to be included in a particular embodiment are illustrated in solid lines, while elements that are optional are illustrated in dashed lines. However, elements that are shown in solid lines may not be essential and, in some embodiments, may be omitted without departing from the scope of the present disclosure.

FIG. 1 is a schematic representation of a hydrocarbon well 10 including a wellbore tubular 50 with an aperture 60 that may be at least partially sealed by sealing devices 70, according to the present disclosure. Hydrocarbon well 10 includes a wellbore 20 that extends within a subterranean formation 42. Wellbore 20 additionally or alternatively may extend, or may be referred to herein as extending, within a subsurface region 40 that includes subterranean formation 42 and/or between a surface region 30 and subterranean formation 42. Subterranean formation 42 may include a reservoir fluid 44, such as a hydrocarbon, or hydrocarbon fluid.

Wellbore tubular 50 extends within wellbore 20. Wellbore tubular 50 includes an elongate tubular body 52, which has and/or defines an inner surface 56 and an outer surface 58. Inner surface 56 defines a tubular conduit 54, and outer surface 58 faces toward and/or contacts subsurface region 40 and/or subterranean formation 42. Examples of wellbore tubular 50 include a casing string and/or inter-casing tubing.

Wellbore tubular 50 also includes at least one aperture 60, which extends through elongate tubular body 52 and/or between inner surface 56 and outer surface 58 of the elongate tubular body. Aperture 60 permits, or is configured to permit, fluid communication between tubular conduit 54 and subterranean formation 42.

Hydrocarbon well 10 further includes at least one sealing device 70. Sealing device 70 is seated on and/or is operatively engaged with aperture 60 and forms an at least partial fluid seal with the aperture. Stated another way, sealing device 70 obstructs, or at least partially obstructs, fluid flow of a wellbore fluid 22, which extends within tubular conduit 54, from the tubular conduit and into the subterranean formation.

During operation of hydrocarbon wells 10, a given aperture 60 may be created, generated, and/or opened to permit fluid flow therethrough. As an example, aperture 60 may be created and/or generated by a shape charge perforation gun. As another example, hydrocarbon well 10 may include one or more selective stimulation ports 62, which may be selectively opened to permit fluid flow through an aperture 60 that is selectively defined by the selective stimulation port. Selective stimulation ports 62, when present and/or utilized, may have a pre-formed sealing device seat, which is formed prior to the wellbore tubular being positioned within the subterranean formation, and may be configured to form a fluid seal with the sealing device. Examples of selective stimulation ports 62 that may be included in and/or utilized with hydrocarbon wells 10, according to the present disclosure, are disclosed in U.S. Provisional Patent Application Nos. 62/262,034 and 62/262,036, which were filed on Dec. 2, 2015, and U.S. Provisional Patent Application No. 62/263069, which was filed on Dec. 4, 2015, and the complete disclosures of which are hereby incorporated by reference.

After creation, generation, and/or opening of aperture 60, a stimulant fluid may be provided to tubular conduit 54, such as from surface region 30, and may flow into subterranean formation 42 via the aperture. The stimulant fluid may stimulate a given region of the subterranean formation, such as by dissolving a respective portion of the subterranean formation and/or by fracturing a respective portion of the subterranean formation. Subsequently, a sealing device 70 may be provided to tubular conduit 54, such as from surface region 30, and may flow, via the tubular conduit, into operative engagement with the given aperture. The sealing device may seal, or at least partially seal, the given aperture, thereby restricting fluid flow therethrough. This process may be repeated any suitable number of times to stimulate any suitable number of regions of the subterranean formation.

FIGS. 2-4 provide more detailed examples of wellbore tubulars 50, of apertures 60, and/or of sealing devices 70, according to the present disclosure, that may engage with and/or seal apertures 60. FIGS. 2-4 may include and/or be more detailed representations of a portion of hydrocarbon well 10 of FIG. 1. As such, any of the structures, functions, and/or features of wellbore tubulars 50, apertures 60, and/or sealing devices 70 that are discussed herein with to reference to any of FIGS. 2-4 may be included in and/or utilized with hydrocarbon wells 10 of FIG. 1 without departing from the scope of the present disclosure. Similarly, any of the structures, functions, and/or features of hydrocarbon wells 10, which are illustrated in FIG. 1, may be utilized with wellbore tubulars 50, apertures 60, and/or sealing devices 70 of FIGS. 2-4 without departing from the scope of the present disclosure.

FIG. 2 is a schematic top view illustrating examples of apertures 60 that may be sealed by sealing devices according to the present disclosure. FIG. 3 is a schematic side view illustrating examples of a conventional ball sealer 78 sealing an aperture 60 and/or of initial engagement between a sealing device 70, according to the present disclosure, and the aperture. FIG. 4 is a schematic side view illustrating examples of a sealing device 70, according to the present disclosure, sealing an aperture 60.

As illustrated in solid lines in FIGS. 2-4, apertures 60 ideally would be circular, or at least substantially circular, when viewed in the top view of FIG. 2. However, as discussed herein and illustrated in dashed lines in FIGS. 2-4, apertures 60 may, in reality, be non-circular, not circular, elongate, and/or oblong in shape. As an example, flow of the stimulant fluid through the aperture may wear and/or corrode an aperture-defining body 64 that defines the aperture. Examples of aperture-defining body 64 include wellbore tubular 50 and/or a selective stimulation port 62 that is operatively attached to the wellbore tubular. Such wear and/or corrosion may cause a shape of the aperture to change from the circular shape that is illustrated in solid lines to the more oblong, or non-circular, shape that is illustrated in dashed lines.

As another example, aperture 60 may be formed, within wellbore tubular 50, by a shape charge perforation gun. Such shape charge perforation guns often may produce and/or generate oblong and/or non-circular apertures, such as those illustrated in dashed lines in FIGS. 2-4.

As illustrated in FIG. 3, conventional ball sealers 78, which may be spherical and relatively rigid, may be effective at sealing apertures 60 that are circular, or at least substantially circular, such as the circular aperture 60 that is illustrated in solid lines in FIG. 3. However, conventional ball sealers 78 may be ineffective at sealing apertures that are non-circular, or oblong, such as aperture 60 that is illustrated in dashed lines in FIG. 3. Under these conditions, and as indicated at 80, a leakage pathway may permit fluid flow between tubular conduit 54 and subterranean formation 42 even when conventional ball sealer 78 is seated on the oblong aperture.

Similar to conventional ball sealer 78, and as illustrated in FIG. 3, sealing devices 70 according to the present disclosure and/or sealing device bodies 72 thereof may be spherical, or at least substantially spherical, prior to engagement with wellbore tubular 50 and/or after initial engagement with wellbore tubular 50. Additionally or alternatively, sealing devices 70 and/or sealing device bodies 72 thereof may be shaped to operatively engage with aperture 60 and to form an at least partial fluid seal with the aperture. As examples, sealing devices 70 and/or sealing device bodies 72 thereof may be bulbous, at least substantially bulbous, egg-shaped, at least substantially egg-shaped, ovoid, and/or at least substantially ovoid.

However, and in contrast with conventional ball sealers 78, sealing devices 70 according to the present disclosure may be relatively more compliant and/or flexible. As such, and as illustrated in FIG. 4, at least a region of sealing devices 70 according to the present disclosure may be configured to deform and/or to conform to a shape of aperture 60 even if the aperture is oblong and/or non-circular in shape. This deformation and/or conformance of the sealing device to the shape of the aperture may permit sealing devices 70 to form an improved fluid seal of aperture 60 when compared to the conventional ball sealers.

Sealing devices 70 may conform to the shape of aperture 60 in any suitable manner. As an example, wellbore tubular 50 may be configured to resist, operate under, and/or be utilized with a maximum design pressure differential in which a pressure within tubular conduit 54 is greater than a pressure within subterranean formation 42. Under these conditions, sealing devices 70 may be configured such that a threshold fraction of the sealing device is extruded through, or into, the aperture at the design pressure differential. Stated another way, and when the pressure within the tubular conduit is greater than the pressure within the subterranean formation, a pressure force 90 (as illustrated in FIG. 4) may act on sealing device 70 and/or may press, or urge, the threshold fraction of sealing device 70 into aperture 60 and/or past an inner surface 51 of wellbore tubular 50. Examples of the threshold fraction of the sealing device include at least 10 volume percent, at least 20 volume percent, at least 30 volume percent, and/or at least 40 volume percent of the sealing device. Additionally or alternatively, the threshold fraction of the sealing device may be at most 50 volume percent, at most 40 volume percent, at most 30 volume percent, and/or at most 20 volume percent of the sealing device.

It is within the scope of the present disclosure that sealing device 70 may be configured such that the threshold fraction of the sealing device is extruded through the aperture without damage to the sealing device. As examples, the threshold fraction of the sealing device may be extruded through the aperture without tearing the sealing device, without permanently deforming the sealing device, and/or without plastically deforming the sealing device.

When the sealing device is extruded into the aperture, at least a region, or fraction, of sealing device body 72 may be deformed to a percent elongation of at least 25 percent, at least 50 percent, at least 75 percent, at least 100 percent, at least 150 percent, and/or at least 200 percent. This may include deformation of the region, or fraction, of the sealing device body without damage to, permanent deformation of, and/or plastic deformation of the sealing device body.

Returning to FIG. 1, and when sealing device 70 is positioned within wellbore tubular 50, a density of the sealing device may be within a threshold percentage of a density of wellbore fluid 22. Examples of the threshold percentage of the density of the wellbore fluid include threshold percentages of at least 80 percent, at least 85 percent, at least 90 percent, at least 95 percent, and/or at least 100 percent. Additionally or alternatively, the threshold percentage of the density of the wellbore fluid may be at most 125 percent, at most 120 percent, at most 115 percent, at most 110 percent, at most 105 percent, and/or at most 100 percent. Additionally or alternatively, the sealing device may be neutrally buoyant, or at least substantially neutrally buoyant, within the wellbore fluid.

As discussed, sealing devices 70 disclosed herein may be configured to deform, or to deform to a greater extent than, conventional ball sealers when operatively engaged with apertures 60 and/or when extruded into apertures 60 by pressure force 90 (as illustrated in FIG. 4). Additionally or alternatively, sealing devices 70 disclosed herein may be configured to be extruded into apertures 60 to a greater extent when compared to conventional ball sealers and/or may be configured to more fully conform to the shape of oblong apertures 60 when compared to conventional ball sealers. With this in mind, sealing device body 72 may have and/or exhibit any suitable material property and/or properties that may permit and/or facilitate a desired level of deformation, a desired extent of extrusion into apertures 60, and/or a desired level of conformation to the shape of apertures 60. Additionally or alternatively, the material properties of sealing device body 72 may permit the desired level of deformation, the desired extent of extrusion and/or the desired level of conformation without damage to the sealing device body.

As an example, sealing device body 72 may have, define, and/or exhibit a hardness of at least 55 durometer, at least 60 durometer, at least 65 durometer, at least 70 durometer, and/or at least 75 durometer. Additionally or alternatively, the hardness of the sealing device body may be at most 80 durometer, at most 75 durometer, at most 70 durometer, at most 65 durometer, and/or at most 60 durometer. The hardness of the sealing device body may be referred to herein as a Shore hardness of the sealing device body.

As another example, sealing device body 72 may have, define, and/or exhibit a tensile strength of at least 14 megapascals (MPa), at least 15 Mpa, at least 16 Mpa, at least 17 Mpa, at least 18 Mpa, at least 19 Mpa, and/or at least 20 Mpa. Additionally or alternatively, the tensile strength of the sealing device body may be at most 24 Mpa, at most 23 Mpa, at most 22 Mpa, at most 21 Mpa, at most 20 Mpa, at most 19 Mpa, and/or at most 18 Mpa.

As yet another example, sealing device body 72 may have, define, and/or exhibit a percent elongation of at least 250 percent, at least 275 percent, at least 300 percent, at least 325 percent, at least 350 percent, at least 375 percent, and/or at least 400 percent. Additionally or alternatively, the percent elongation of the sealing device body may be at most 500 percent, at most 475 percent, at most 450 percent, at most 425 percent, at most 400 percent, at most 375 percent, and/or at most 350 percent.

As another example, sealing device body 72 may have, define, and/or exhibit a 100% tensile stress of at least 1.4 Mpa, at least 1.75 Mpa, at least 2 Mpa, at least 2.25 Mpa, at least 2.5 Mpa, at least 3 Mpa, and/or at least 4 Mpa. Additionally or alternatively, the 100% tensile stress of the sealing device body may be at most 5.2 Mpa, at most 4.75 Mpa, at most 4.5 Mpa, at most 4.25 Mpa, at most 4 Mpa, at most 3.5 Mpa, and/or at most 3 Mpa.

As yet another example, sealing device body 72 may have, define, and/or exhibit a die C tear resistance of at least 26 kilonewtons/meter (kN/m), at least 28 kN/m, at least 30 kN/m, at least 32 kN/m, at least 34 kN/m, at least 36 kN/m, and/or at least 38 kN/m. Additionally or alternatively, the die C tear resistance of the sealing device body may be at most 44 kN/m, at most 42 kN/m, at most 40 kN/m, at most 38 kN/m, at most 36 kN/m, at most 34 kN/m, and/or at most 32 kN/m.

As another example, sealing device 70 and/or sealing device body 72 thereof may have, define, and/or exhibit a specific gravity of at least 0.6, at least 0.7, at least 0.8, at least 0.9, at least 1.0, and/or at least 1.1. Additionally or alternatively, the specific gravity of the sealing device and/or of the sealing device body may be at most 1.3, at most 1.25, at most 1.2, at most 1.15, at most 1.1, and/or at most 1.05. As an example, the specific gravity of the sealing device and/or of the sealing device body may be selected, specified, and/or tailored such that the density of the sealing device is within the threshold percentage of the density of the wellbore fluid and/or such that the sealing device is neutrally buoyant within the wellbore fluid. Examples of the wellbore fluid include water, a drilling mud, a hydrocarbon, a supercritical fluid, carbon dioxide, and/or supercritical carbon dioxide.

It is within the scope of the present disclosure that sealing device 70 may include and/or be a single-piece, or monolithic, sealing device 70. Stated another way, sealing device 70 and/or sealing device body 72 thereof may be formed, at least substantially formed, and/or entirely formed from a body material, or from a single body material. Examples of the body material include a polymeric material, a rubber, a nitrile rubber, a hydrogenated nitrile butadiene rubber (HNBR), and/or a highly saturated HNBR.

Additionally or alternatively, it is also within the scope of the present disclosure that sealing device 70 and/or sealing device body 72 thereof may include and/or be defined by a plurality of distinct and/or separate materials and/or structures that may be combined to produce and/or generate the sealing device. As an example, and as illustrated in FIG. 4, sealing device 70 and/or sealing device body 72 thereof may include an outer covering 74 and a core 76. Outer covering 74 may be formed from a covering material, and core 76 may be formed from a core material that is different from the covering material.

Examples of the covering material include the body material, which is disclosed herein. An additional example of the covering material includes a wear-resistant material. Examples of the core material include a material with a density that is less than a density of the covering material, a buoyant material, a foam, a syntactic foam, a liquid, a metal, and/or a rigid material.

When core 76 includes the material with the density that is less than the density of the covering material, the core material and/or a ratio of a volume of the core material to a volume of the covering material in a given sealing device 70 may be utilized to selectively adjust and/or vary the density, or an overall, or net, density of the sealing device. Such a configuration may permit sealing devices 70 that include cores 76 to have a lower density, or be neutrally buoyant in a lower density wellbore fluid, than would be achievable with a sealing device that is formed from a single body material. A ratio of the density of the core material to the density of the covering material may have any suitable value, examples of which include ratios of at most 0.9, at most 0.8, at most 0.7, at most 0.6, at most 0.5, at least 0.2, at least 0.3, at least 0.4, at least 0.5, and/or at least 0.6.

When core 76 includes the rigid material, the rigid material may be sized and/or shaped to resist extrusion of an entirety of sealing device 70 through a given aperture 60. Stated another way, the rigid material may resist deformation, or at least significant deformation, when the sealing device is operatively engaged with aperture 60 and subjected to pressure force 90. In contrast, outer covering 74 and/or the covering material thereof may deform, thereby permitting the sealing device to seal non-circular apertures 60, as discussed herein.

When sealing device 70 includes both outer covering 74 and core 76, it is within the scope of the present disclosure that the material properties of sealing device body 72 that are disclosed herein (e.g., the hardness, tensile strength, percent elongation, 100% tensile stress, die C tear resistance, and/or specific gravity of the sealing device body) may include and/or be a “net” or an “effective” material property of the overall sealing device, including both outer covering 74 and core 76 thereof. Additionally or alternatively, it is also within the scope of the present disclosure that these material properties may apply only to outer covering 74 and/or that core 76 may have and/or define material properties that are outside of the listed ranges.

As an example, the tensile strength of the core may be at least 2, at least 3, at least 4, at least 5, at least 6, at least 7, at least 8, at least 9, or at least 10 times greater than the tensile strength of the outer covering and/or than any of the tensile strength values for the outer covering that are disclosed herein. As another example, the hardness of the core may be at least 2, at least 3, at least 4, at least 5, at least 6, at least 7, at least 8, at least 9, or at least 10 times greater than the hardness of the outer covering and/or than any of the hardness values of the outer covering that are disclosed herein.

As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally.

As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

As used herein, the phrase, “for example,” the phrase, “as an example,” and/or simply the term “example,” when used with reference to one or more components, features, details, structures, embodiments, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, embodiment, and/or method is an illustrative, non-exclusive example of components, features, details, structures, embodiments, and/or methods according to the present disclosure. Thus, the described component, feature, detail, structure, embodiment, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, embodiments, and/or methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, embodiments, and/or methods, are also within the scope of the present disclosure.

INDUSTRIAL APPLICABILITY

The sealing devices, wellbore tubulars, and hydrocarbon wells disclosed herein are applicable to the oil and gas industries.

It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure. 

1. A sealing device, comprising: a sealing device body sized and shaped to operatively engage with an aperture in a wellbore tubular to form an at least partial fluid seal with the aperture, wherein the sealing device body has: a hardness of 55-80 durometer; (ii) a tensile strength of 14-24 megapascals (Mpa); (iii) a percent elongation of 250-500 percent; (iv) a 100% tensile stress of 1.4-5.2 Mpa; and (v) a die C tear resistance of 26-44 kilonewtons/meter (kN/m).
 2. The sealing device of claim 1, wherein a specific gravity of the sealing device body is at least 0.6 and at most 1.3.
 3. The sealing device of claim 1, wherein at least one of: (i) the sealing device body is at least substantially formed from a body material; (ii) an entirety of the sealing device body is formed from the body material; and (iii) the sealing device body is formed entirely from a single body material.
 4. The sealing device of claim 3, wherein the body material includes at least one of: (i) a polymeric material; (ii) a rubber; (iii) a nitrile rubber; (iv) a hydrogenated nitrile butadiene rubber (HNBR); and (v) a highly saturated HNBR.
 5. The sealing device of claim 1, wherein the sealing device body includes an outer covering, which is formed from a covering material, and a core, which is formed from a core material that is different from the covering material.
 6. The sealing device of claim 5, wherein the covering material includes at least one of: (i) a polymeric material; (ii) a rubber; (iii) a nitrile rubber; (iv) a hydrogenated nitrile butadiene rubber (HNBR); and (v) a highly saturated HNBR.
 7. The sealing device of claim 5, wherein the core material includes at least one of: (i) a material with a density that is less than a density of the covering material; (ii) a buoyant material; (iii) a foam; (iv) a syntactic foam; and (v) a rigid material.
 8. The sealing device of claim 1, wherein the sealing device body is at least one of: (i) spherical; (ii) at least substantially spherical; (iii) bulbous; (iv) at least substantially bulbous; (v) egg-shaped; (vi) at least substantially egg-shaped; (vii) ovoid; and (viii) at least substantially ovoid.
 9. A wellbore tubular, comprising: an elongate tubular body having an inner surface that defines a tubular conduit and an outer surface that is configured to face a subterranean formation; an aperture extending through the elongate tubular body to permit fluid communication between the tubular conduit and the subterranean formation; and the sealing device of claim 1, wherein the sealing device is operatively engaged with the aperture and forms an at least partial fluid seal with the aperture to obstruct flow of a wellbore fluid from the tubular conduit into the subterranean formation.
 10. The wellbore tubular of claim 9, wherein a threshold fraction of the sealing device is extruded through the aperture.
 11. The wellbore tubular of claim 10, wherein the threshold fraction of the sealing device is at least 10 volume present and at most 50 volume present.
 12. The wellbore tubular of claim 10, wherein the threshold fraction of the sealing device is extruded through the aperture without tearing the sealing device.
 13. The wellbore tubular of claim 9, wherein at least a region of the sealing device body is deformed to a percent elongation of at least 100 percent.
 14. The wellbore tubular of claim 9, wherein a density of the sealing device is within a threshold percentage of a density of the wellbore fluid, wherein the threshold percentage of the density of the wellbore fluid is at least 80 percent and at most 125 percent.
 15. The wellbore tubular of claim 9, wherein the sealing device is at least substantially neutrally buoyant within the wellbore fluid.
 16. The wellbore tubular of claim 9, wherein the aperture is defined by at least one of: (i) a perforation formed within the tubular body, wherein the perforation is an irregularly shaped perforation formed by a shape charge perforation device; and (ii) a selective stimulation port that is operatively attached to the tubular body, wherein the selective stimulation port includes a pre-formed sealing device seat, which is formed prior to the wellbore tubular being positioned within the subterranean formation.
 17. The wellbore tubular of claim 9, wherein the aperture is at least one of: not circular; and (ii) elongate.
 18. The wellbore tubular of claim 9, wherein at least a portion of the sealing device body is conformed to a non-circular shape of the aperture.
 19. The wellbore tubular of claim 9, wherein the wellbore tubular includes at least one of: a casing string; and (ii) inter-casing tubing.
 20. A hydrocarbon well, comprising: a wellbore extending within a subterranean formation; and the wellbore tubular of claim 9, wherein the wellbore tubular extends within the wellbore. 